In Steam Assisted Gravity Drainage (SAGD) operations, steam is the primary means of mobilizing the in-situ bitumen or heavy oil-Bitumen (HO-B) resource. The cost of steam generation and delivery accounts for a significant portion of ongoing operational expenditures of the recovery process, thus any efficiency gains in delivering steam to the reservoir makes the entire process more cost effective. Two significant challenges that impact the process efficiency are the occurrence of steam breakthrough along the lateral and steam non-conformance. Both of these issues are largely due to the presence of reservoir heterogeneities. A possible solution to address these challenges is the inclusion of flow control devices (FCDs) in SAGD completions.

In order to quantify the impact of including FCDs in the SAGD process, this study was performed by numerical analysis with a model built from publicly available geological data representing the Surmount field of Alberta. The model has the reservoir fully coupled to a discretized wellbore. With this model, the study is able to capture the presence of heterogeneities and the effect with respect to steam breakthroughs and non-conformance. Several wellbore variations are tested in this study, including a Base Case having a traditional completion (long string/short string completion) and other cases with various FCD configurations and arrangements.

The results of the modeling process show that the inclusion of FCDs positively impacts the SAGD process by minimizing the occurrences of breakthroughs, improving conformance and by increasing the volumetric sweep efficiency of the process. Included is a comparison of the results from the Base Case versus other cases. The comparison presents a conclusion which demonstrates that deploying FCDs in SAGD wells provides an economic benefit. The economic comparison is based on net present value (NPV) analysis and payout of the various cases. This study is relevant because it demonstrates how FCDs can be employed to overcome geological challenges that would otherwise result in non-conformance and steam breakthrough. By overcoming these challenges the project economics improve. The functionality of these devices also presents the possibility of using slimmer and longer completions for the SAGD well pairs which will improve project economics even more.

In oil sands in situ operations using steam-assisted gravity drainage (SAGD), achieving effective communication between the injector and producer with a reasonable conformance is crucial for the success of SAGD conversion and the following ramp-up phase. The start-up operation normally relies on heat conduction phenomena for establishing communication between the wells. For oil sands reservoirs containing extremely high viscosity bitumen, establishing the temperature profile required for SAGD conversion using conduction as the only heating mechanism is not efficient and can take 90 to 120 days to achieve. Start-up operation can be accelerated by enhancing the rate of convective heat transfer to the formation by techniques such as bullheading and cold/hot dilation.

At Nexen’s Long Lake in-situ SAGD project, the use of higher injection pressures to enhance start-up is limited by the presence of high water saturation zones within the bitumen pay zone (“lean zones”), an adjacent Quaternary-age fresh water-bearing channel, and shallow formation depth. In order to overcome these constraints, an approach using solvent injection in a warm system with enhanced injectivity was successfully designed and implemented. In this approach, the solvent was injected in a high bitumen saturation system after circulating the well for about 70 days. Then, the solvent was chased with hot water into the formation to deliver the solvent deeper into the formation and enhance the rate of solvent-bitumen mixing during the soaking time.

This paper reviews the design criteria, well selection process, and implementation of warm solvent injection in the conducted pilot in the start-up phase of Pad 13 at Long Lake. It also compares production responses of solvent-treated and control wells with comparable reservoir properties within the same pad to evaluate the performance of the designed pilot. Review of the production data shows that the solvent-treated well pair has outperformed all the other well pairs of the pad with no apparent conformance issues. This well had a quick ramp-up which is considerably faster than the average ramp up time at the Long Lake project. The collected data suggests that applying solvent-assisted start-up in systems that have enhanced mobility by pre-circulation of steam can shorten the circulation time and accelerate the ramp-up phase after SAGD conversion.

Controlling the steam channeling is a major challenge for increasing production in heavy oil reservoirs developed by steam injection. The conventional gel used in water flooding reservoirs always has poor heat resistance, so this paper proposed a novel high-temperature (HTG) gel blocking agent on the basis of a laboratory experimental study. The HTG consists of nonionic filler and unsaturated amide monomer with graft polymerization and crosslinking. The optimal gel system has a high gelling strength and controllable gelation time, which is achieved through incomplete orthogonal design method. Then the stability and plugging performance are studied through singular and parallel sand-pack experiments.

The results indicate that the HTG has strong salt resistance and dilution resistance. In addition, the HTG can still maintain high strength at 200ªC for 72h. The singular sand-pack experiments suggest that the HTG has good injectability that ensures the on-site construction safety. Moreover, the HTG has a high breakthrough pressure gradient after gelling and could keep the plugging ratio above 99.8% after gel breakthrough when the subsequent injected volume reaches 10PV. The results obtained in parallel sand-pack experiments show that the HTG can effectively plugging the steam channeling after injecting into the high permeability sand-pack from the production end, and force the subsequent steam to enter the low permeability sand-pack. That raises the producing degree of the low permeability sand-pack. Finally, the difference between high and low permeability sand-pack liquid production is reduced by 99.98%,indicating that the producing profile is tremendously improved, and the oil recovery is enhanced by 41.34%. As a result, the novel HTG blocking agent can be used to control the steam channeling in heavy oil reservoir.

Several recovery processes have been proposed for heavy oil and oil sand reservoirs, depending on the reservoir and fluid properties. Among these, steam-assisted gravity drainage (SAGD) is widely used, and surface mining is considered the best approach in very shallow depths. However, deposits exist that are too shallow for SAGD but too deep for mining, requiring special techniques to recover the hydrocarbon economically. In addition, significant reserves are left behind as stranded reserves, as well as reserves that are usually characterized with weak caprock integrity and without enough pay thickness for SAGD to be economically viable. This paper focuses on a new technology that involves creating several mechanically induced inclusions in a single well. The production process is similar to a single-well SAGD. This method is proposed to assist both more uniform steam injection and bitumen production processes. The current setup is developed for vertical well applications; however, upon successful planning, the next version will be employed for horizontal applications.

The current system consists of a vertical well with multiple vertical inclusions, which are used for simultaneous steam injection and liquid production purposes. Steam is injected into the upper part of the formation, and the drained liquid is collected at the bottom of the inclusions. Unlike the conventional steam chamber geometry in SAGD processes, steam moves outward from the inclusion faces into the formation and tends to move laterally out and vertically upward over time. Simulation studies of the system show that the success of such a technique depends on the inclusion dimensions as well as injection rate and pressure. In this study, the effects of inclusion dimensions and steam properties on the performance of such a process are investigated. Reservoir simulations of realistic reservoir conditions show promising results in terms of cumulative steam oil ratio (CSOR) and production rate. Early peak oil production occurred at approximately 100 days from the startup, and the CSOR dropped to under 3 m3/m3 after 100 days. The optimum inclusion dimensions and the best injection scenario for different net pays at different depths and geological conditions are illustrated in the paper.

Fully heterogeneous three-dimensional SAGD simulation models are computationally expensive to evaluate, necessitating the need for simpler models that can capture the overall physics of the process while reducing computation time. This paper sheds some insights into the effect of permeability heterogeneity on SAGD performance, and presents both a physics-based upscaling technique that considers the unique geometry of the steam-plume during the SAGD process, as well as a statistical upscaling scheme based on variable selection and multivariate non-linear regression.

Full physics, two-dimensional SAGD simulations were performed using several stochastic shale models representing different proportions. Subsequently, the vertical variability in the models was averaged using a flow-based upscaling technique to obtain an effective anisotropic ratio. The performance of the upscaled models was assessed using full physics numerical simulation. It was observed that the upscaled anisotropic models gave different results compared to the fully heterogeneous models. The discrepancy between the heterogeneous and anisotropic models is largely due to upscaling. Two approaches were formulated to address this. The first approach iteratively adjusts the anisotropic permeability of the 2D model until a match to the 3D heterogeneous model was achieved. Then a non-linear regression model between the heterogeneous model parameters and the history-matched anisotropic permeability was formulated. In the second approach, an upscaling method considering the flux due to convergent flow towards a line sink was developed.

A key result presented in this paper is that heterogeneity plays a significant role in SAGD performance. Factors such as shale correlation length and proportion affect both the initial steam rise and the lateral spread of the chamber. Traditional upscaling techniques assuming power averages or flow-based assuming uniform flow over a plane are inadequate for approximating heterogeneous models. Statistical schemes such as the one presented in this paper perform much better in capturing the recovery characteristics of the SAGD process in heterogeneous media. Considerations such as optimum well pair spacing and optimal steam-oil ratio for maximizing bitumen recovery require quick evaluation of multiple scenarios and that may be possible using the approach presented in the paper.

It has long been known that heavy oil and bitumen recovery by SAGD and CSS processes is accompanied by significant production of acid gases, as well as solution gas. Since the old laboratory studies of aquathermolysis from the 1970’s and 1980’s, there has been considerable development in the knowledge concerning production of methane and acid gases from Athabasca, Cold Lake, Peace River, Venezuela and Utah oil sands. It is found that both GOR and gas composition may vary with the deposits concerned. There is considerable divergence of opinion about the chemical origin of some gases, notably carbon dioxide. This affects the methods of control that may be available in operating individual reservoirs, and the matter is discussed. Also discussed will be the means of taking advantage of aquathermolysis phenomenon. It has been shown that both the GOR and gas composition of a SAGD project can be calculated from first principles. This permits estimation of the daily throughput of hydrogen sulphide and therefore allows a prediction or control of the requirements for sulphur recovery. The control of scale in SAGD plants has also been achieved by application of the current state of knowledge. Finally, there are implications for hydrogen sulphide release during loss of well control, an important regulatory aspect.

Reservoir recovery processes are complex and typically entail several physical or chemical mechanisms. Polymer flooding has often been depicted to be dominated by one mechanism: water viscosification reduces the mobility ratio, and stabilizes the displacement front to increase oil recovery. Increasingly though the contribution of mechanisms other than water viscosification is becoming understood. This paper points out two novel insights into polymer flooding: (1) the intrinsic value of the polymer is likely being overestimated and (2) the practice of operating the polymer flood with incomplete voidage replacement may indeed be optimal. The conversion of a conventional waterflood to a polymer flood entails significant injectivity reduction, up to 50% or more. The maintenance of complete voidage replacement (VRR = 1) would thus require an increase in the number of injectors, or a reduction of total production rate or both. As both interventions reduce the economic returns, most projects operate with incomplete voidage replacement (VRR < 1). We have previously reported that a VRR < 1 improves the waterflood response of heavy oil reservoirs. Thus using the VRR = 1 waterflood as the comparison benchmark to the polymer response may overestimate the value of viscosification – the intrinsic value of the polymer. To quantify this, we have performed numerical simulations of polymer flooding for VRRs ranging from 0.4 to 1.4, deconvolving the relative contributions of the viscosification and VRR < 1 mechanisms. We observe that a polymer flood operated with VRR > 1 (above the oil bubble point) underperforms a polymer flood with a VRR < 1 by as much as one third. We conclude that the intrinsic value of the polymer is overestimated.

The production of gaseous sulfur-containing species during the steam-assisted recovery of heavy oil and bitumen have important consequences for both economics and safety. Factors such as the effects of mineral matrices require laboratory data to produce accurate models. To study mineral effects on gas production we studied a well-characterized oil-containing core and the isolated crude oil from that core. The samples were run at 250-300°C in the continued presence of liquid water for 24 hours. The reaction products of all experiments include gases, oil flotate, oil sinkate, water-soluble products, and water- insoluble residues. All reaction products were studied with a variety of analytical techniques, including FTIR spectroscopy, chromatographic fractionation (SARA analysis), GC-MS, pyrolysis GCMS and GC-FPD/TCD. These techniques were applied to whole oil, maltenes and asphaltene fractions. Physical properties including viscosity and density were also measured. Our data provide insights into the physical and chemical consequences of steam assisted recovery of heavy oils and bituments from sedimentary rock reservoirs and reveal that geological and geochemical context is an essential consideration.

This study focuses on the investigation of the mechanism behind surface heave induced by thermal recovery. Injection of steam into oilsand reservoirs results in changes in temperature and pore pressure within the subsurface. These changes can induce a reduction of effective stress, which provides initial containment of bitumen. Irreversible shear/tensile deformation of the caprock and overburden might be one of the unwanted consequences of such process.

We developed a work flow incorporating the Finite Difference Method (FDM) and Finite Element Method (FEM). Heat and fluid flows are computed using FDM with CMG-STARS and elastic/plastic deformation estimations are done through Abaqus FEM simulation software. The Mohr-Coulomb yield criterion and the non-associated flow rule is used to assess the plastic failure in the reservoir and caprock. This work flow is used to assess the impact of the SAGD process on the integrity of caprock.

The geomechanical model is calibrated with surface deformation measurements. Parameter search is performed to study how geomechanical parameters influence the expression of reservoir deformation at the surface. The uncertainty associated with the modeled results shows the need for a more refined geomechanical model, considering the heterogeneous nature of geological structure in the region of interests.

An excellent design of steam injection projects requires accurate prediction of bottomhole steam pressure, temperature and quality. However, it is not always easy to meet the requirement when we design concentric dual-tubing steam injection schemes due to the complexity of downward steam/water flow in annuli. Also, previous methods for estimating pressure gradient in annuli, such as mechanistic models and empirical correlations, are either time-consuming or inaccurate.

In this study, we present a new semi-analytical model to predict steam pressure and temperature in annuli. It is based on Coulter-Bardon equation and on mass and energy balances in the wellbore. A more rigorous thermodynamic behavior of steam/water mixture is taken into account. More importantly, one-to-one correspondence between pressure gradient and temperature gradient of saturated steam is reasonably developed and applied in our further derivation and simplification. It is because of the simplification that we do not have to use mechanistic models or empirical correlations to separately calculate the pressure drop in annuli, which is significantly different from previous work, including Sagar et al. (1991), Alves et al. (1992) and Hasan et al. (1994) models. Our solution procedure is straightforward, the equations of steam pressure, temperature, quality, steady-state heat transfer in the wellbore and transient heat transfer in the formation just need to be coupled and solved iteratively for each segment.

Our model is validated by comparison with measured field data from Liaohe Oilfield, Petro China. The results indicate that the direction of heat transfer between inner and outer tubing depends on wellhead conditions and temperature drop in each tubing. We also show that the equivalent hydraulic diameter is not always a suitable characteristic dimension for steam/water flow in annuli. Moreover, the paper shows that our method can also be applied to single-tubing steam injection design. The predicted results from our modified model are also compared with those from CMG simulator and previous work in our study.